National Fuel Gas Company. Analyst Day Presentation

Transcription

1 National Fuel Gas Company Analyst Day Presentation November 19, 2013

2 Analyst Day - November 2013 Corporate National Fuel Gas Company Safe Harbor For Forward Looking Statements This presentation may contain forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995, including statements regarding future prospects, plans, performance and capital structure, anticipated capital expenditures and completion of construction projects, as well as statements that are identified by the use of the words anticipates, estimates, expects, forecasts, intends, plans, predicts, projects, believes, seeks, will, may, and similar expressions. Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The Company s expectations, beliefs and projections contained herein are expressed in good faith and are believed to have a reasonable basis, but there can be no assurance that such expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors, the following are important factors that could cause actual results to differ materially from results referred to in the forward-looking statements: factors affecting the Company s ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including among others geology, lease availability, title disputes, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations; changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing; changes in the price of natural gas or oil; impairments under the SEC s full cost ceiling test for natural gas and oil reserves; uncertainty of oil and gas reserve estimates; significant differences between the Company s projected and actual production levels for natural gas or oil; changes in demographic patterns and weather conditions; changes in the availability, price or accounting treatment of derivative financial instruments; governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, allowed rates of return, rate design and retained natural gas), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; delays or changes in costs or plans with respect to Company projects or related projects of other companies, including difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators; financial and economic conditions, including the availability of credit, and occurrences affecting the Company s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company s credit ratings and changes in interest rates and other capital market conditions; changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers ability to pay for, the Company s products and services; the creditworthiness or performance of the Company s key suppliers, customers and counterparties; economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities, acts of war, cyber attacks or pest infestation; changes in price differential between similar quantities of natural gas at different geographic locations, and the effect of such changes on the demand for pipeline transportation capacity to or from such locations; other changes in price differentials between similar quantities of oil or natural gas having different quality, heating value, geographic location or delivery date; significant differences between the Company s projected and actual capital expenditures and operating expenses; changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities; the cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; or increasing costs of insurance, changes in coverage and the ability to obtain insurance. Forward-looking statements include estimates of oil and gas quantities. Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible under existing economic conditions, operating methods and government regulations. Other estimates of oil and gas quantities, including estimates of probable reserves, possible reserves, and resource potential, are by their nature more speculative than estimates of proved reserves. Accordingly, estimates other than proved reserves are subject to substantially greater risk of being actually realized. Investors are urged to consider closely the disclosure in our Form 10-K available at You can also obtain this form on the SEC s website at For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements, see Risk Factors in the Company s Form 10-K for the fiscal year ended September 30, 2012 and Forms 10-Q for the periods ended December 31, 2012, March 31, 2013 and June 30, The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence of unanticipated events. 2

3 Analyst Day - November 2013 Corporate National Fuel Gas Company Analyst Day Schedule of Speakers Presenter Ron Tanski President and Chief Executive Officer Matt Cabell President of Seneca Resources Corporation John McGinnis Senior VP of Seneca Resources Corporation Barry McMahan Senior VP of Seneca Resources Corporation Ron Kraemer President of Empire Pipeline, Inc. VP of National Fuel Gas Supply Corporation Dave Bauer Treasurer and Principal Financial Officer Topic Corporate Overview Exploration & Production Overview Appraisal & Development California Marcellus Operational & Environmental Midstream Businesses Utility Overview Hedging Strategy Financial Wrap-Up 3

4 Analyst Day - November 2013 Corporate Corporate Overview 4

5 Analyst Day - November 2013 Corporate National Fuel Gas Company Exceptional Assets, Focused on Execution Tcfe of Proved Reserves 800,000 Net Acres in Pennsylvania 2.8 MMBbl of Crude Oil Production $191 Million of Midstream EBITDA 5

6 Analyst Day - November 2013 Corporate National Fuel Gas Company A History of Success & A Future of Opportunity Recent Success 35% Production CAGR Since 2010 Nearly $600 Million Invested in New Pipeline Infrastructure De-risked 2,000 Well Locations in the Marcellus 6

7 Analyst Day - November 2013 Corporate Corporate Overview Integrated Businesses Provide Complimentary Benefits Adjusted EBITDA ($ Millions) $600 $450 $300 $150 $0 $280 Upstream (E&P) Tremendous Growth (15% CAGR) $327 $377 $397 $ Fiscal Year Adjusted EBITDA ($ Millions) $250 $200 $150 $100 $50 $0 Adjusted EBITDA ($ Millions) $164 $167 $169 $250 $200 $150 $100 $50 $0 Downstream (Utility) Stability & Financial Strength Midstream Businesses Growth & Predictability (10% CAGR) $131 $123 $121 $152 $ Fiscal Year $160 $ Fiscal Year 7

8 Analyst Day - November 2013 Corporate Corporate Overview Consistent Growth in Low Natural Gas Price Environment Adjusted EBITDA ($ Millions) $1,000 $750 $500 $250 $0 $581 $280 48% $131 23% $164 28% $632 $327 52% $121 19% $167 26% $668 $377 57% $111 17% $169 25% $704 $397 56% $137 19% $160 23% $852 $492 58% $161 19% $172 20% (1) Average NYMEX contract settlement price for the 12-month period Fiscal Year $30 3% Natural gas prices dropped 23% from 2009 to 2013 Fiscal Year Energy Marketing & Other Utility Segment Pipeline & Storage Segment Gathering Segment Natural Gas (1) ($/MMBtu) 2009 $ $ $ $ $3.60 Exploration & Production Segment 8

9 Analyst Day - November 2013 Corporate Corporate Overview Still in the Early Stages of Our Marcellus Growth Story Eastern Development Area Western Development Area Initial Delineation Full Development ( Locations) Initial Delineation Delineation (New Areas/Depths) Optimization & Enhancement Full Development (1,700-2,000 Locations) Optimization & Enhancement Production Decline Delineation (New Areas/Depths) 9

10 Analyst Day - November 2013 Corporate Corporate Overview Formula to Grow Our Marcellus Development Program? High-Quality Reservoir Operating Efficiencies Realized Natural Gas Price Infrastructure & Marketing Increased Capital Deployment National Fuel is maintaining a proactive approach to securing markets for its growing natural gas production 10

11 Analyst Day - November 2013 Corporate Corporate Overview Opportunities to Move Gas Out of the Northeast 100% 75% 50% 25% 0% 31% % of Year that Northeast will be Long Gas Supply 52% 62% 69% The oversupply of natural gas in the Northeast is creating opportunities for the midstream businesses to develop projects to deliver to higher-priced markets such as Eastern Canada and the Southeast Source: TPH Research 76% 86% 90% 93% 11

12 Analyst Day - November 2013 Corporate Corporate Overview Marcellus Infrastructure Growth Still Has Room to Run 2010 to 2013 Expansions Capacity Added 1,819 MDth per day Capital Deployed $422 million Expansions Capacity Planned 1,724 to 2,224 MDth per day Capital Expenditures Planned ~$1.5 billion Plans are in place to deploy significant capital to double the expansion capacity added since

13 Analyst Day - November 2013 Corporate National Fuel Gas Company A History of Success & A Future of Opportunity Future Goals 10-15% Adjusted EBITDA Growth 15-25% Production Growth $1.5 Billion of Midstream Investment Over 5 Years 13

14 Analyst Day - November 2013 Corporate Corporate Overview Maintaining Our View on Corporate Structure Strong Balance Sheet Ability to modestly increase leverage 1.89x Debt/Adjusted EBITDA Balanced Business Mix 58% E&P (1) 42% Midstream/Utility (1) Operational synergies Investment Grade Credit Today Future (2015+) Diversification of businesses provide credit support Leverage is the cheapest cost of capital today More Aggressive Growth Requires Capital Goal is to accelerate value creation Need stronger natural gas prices Additional leverage is limited Result may lead to a shift in business mix Options to Consider Midstream MLP Upstream/Midstream JV In today s commodity price environment, our current structure can handle near-term growth. Look to accelerate development when the economics of doing so are favorable. (1) Based on Adjusted EBITDA 14

15 Analyst Day - November 2013 Upstream Exploration & Production Overview 15

16 Analyst Day - November 2013 Upstream Seneca Resources Seneca s Evolution Total Production Gulf of Mexico Shallow Appalachia ~400% Production Growth (2008 to 2015) 41 Bcfe 43 Bcfe 50 Bcfe 68 Bcfe California (1) Represents the midpoint of current guidance (Fiscal 2014: Bcfe; Fiscal 2015: Bcfe) Marcellus Shale Eastern Development Area Marcellus Shale Western Development Area 83 Bcfe Geneseo Shale (Delineation) Utica Shale (Delineation) 121 Bcfe ~155 Bcfe (1) ~200 Bcfe (1) 16

17 Analyst Day - November 2013 Upstream Seneca Resources Fiscal 2013 Highlights 45% 351% WDA Success Total production increased 45% to Bcfe Replaced 351% of proved reserves Finding & Development Cost: $1.31/Mcfe Marcellus Finding & Development Cost: $0.99/Mcfe Achieved major breakthrough in the Marcellus Shale Western Development Area (WDA) De-risked 1,700 to 2,000 future drilling locations 17

18 Analyst Day - November 2013 Upstream Seneca Resources Disciplined Capital Spending Capital Expenditures ($ Millions) $1,000 $800 $600 $400 $200 $0 Gulf of Mexico (Divested in 2011) East Division (Appalachia) West Division (California/Kansas) $188 (1) $139 $398 $356 $649 $596 $694 $631 $31 $28 $47 $63 $533 $428 $105 $550-$650 $460- $520 $90- $ Forecast Fiscal Year $650-$750 $560- $620 $90- $ Forecast (1) Does not include the $34.9 MM acquisition of Ivanhoe s U.S.-based assets in California, as this was accounted for as an investment in subsidiaries on the Statement of Cash Flows, and was not included in Capital Expenditures 18

19 Analyst Day - November 2013 Upstream Seneca Resources Proven Record of Growth Total Proved Reserves (Bcfe) Natural Gas (Bcf) Crude Oil (MMbbl) , ,549 1, (1) Represents a three-year average U.S. finding and development cost At September 30 Fiscal Years 3-Year F&D Cost (1) ($/Mcfe) $ $ $ $ $ $ F&D Cost = $1.31 Marcellus F&D: $0.99 Doubled Proved Reserves Since % Proved Developed 19

20 Analyst Day - November 2013 Upstream Seneca Resources Best-In-Class Marcellus Shale Reserve Growth 45% 30% 15% 0% -15% 33% (1) Peers consist of AR, COG, EQT, RRC, SWN 2009 to 2012 Proved Reserves CAGR (1) 24% 21% 19% 7% -10% NFG Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 20

21 Analyst Day - November 2013 Upstream Seneca Resources Delivering Tremendous Production Growth Annual Production (Bcfe) Gulf of Mexico (Divested in 2011) East Division (Appalachia) West Division (California/Kansas) Forecast Fiscal Year 2015 Forecast 21

22 Analyst Day - November 2013 Upstream Seneca Resources Delivering More than Just Absolute Growth Total Proved Reserves per Debt-Adjusted Share (Mcfe) Proved Reserves per Debt-Adjusted Share (1) (Mcfe) At September 30 (1) Year-end proved reserves divided by debt-adjusted year-end diluted shares outstanding (2) Annual production per share divided by debt-adjusted year-end diluted shares outstanding Total Production per Debt-Adjusted Share (Mcfe) Total Production per Debt-Adjusted Share (2) (Mcfe) Fiscal Year 22

23 Analyst Day - November 2013 Upstream Marcellus Shale Significant Position & Integral Part of Seneca s Future Company (1) Source: ITG Investment Research, & Company Data (2) Source: Bloomberg - As of November 8, 2013 Net Marcellus Acreage (1) Enterprise Value (2) ($ Billions) Acres per $ Million of EV NFG 780,000 $ RRC 835,000 $ EQT 560,000 $ SWN 337,000 $ AR 334,000 $ COG 200,000 $

24 Analyst Day - November 2013 Upstream Marcellus Shale Factors for Success Acreage Position Quantity & Quality Operating Expertise Control costs Maximize production Gathering, Transportation and Marketing Financial Stability Ability to withstand price swings and market dislocations 24

25 Analyst Day - November 2013 Upstream Marcellus Shale Prolific Pennsylvania Acreage Seneca Fee Seneca Lease 720,000 Acres 60,000 Acres Western Development Area (WDA) Mineral ownership: 83% No royalty; No lease expiration Net revenue interest: 98% Highly contiguous Significant economies of scale Eastern Development Area (EDA) Mostly leased (16-18% royalty) No near-term lease expiration First large expiration: 2018 Ongoing development drilling in Tioga and Lycoming Counties 25

26 Analyst Day - November 2013 Upstream Seneca Acreage Huge Position Varies in Understanding Seneca Fee Seneca Lease Tier I ~200,000 Acres Understanding Seneca s 780,000 Net Acres Northeast Core ~30,000 acres in NE Core Tier I Acres ~200,000 acres Economic less than $4/Mcf Awaiting Evaluation ~250,000 acres Requires Gas Price Above $4/Mcf ~300,000 acres 26

27 Analyst Day - November 2013 Upstream Seneca Acreage Fee Ownership & Contiguity are Beneficial No Royalty No Lease Expiration Seneca s Tier I acreage is approaching Northeast Core economics Contiguous Acreage Blocks 27

28 Analyst Day - November 2013 Upstream Seneca Acreage Seneca s Marcellus Acreage Provides a Unique Advantage Competitor Single Pad Working Interest: 100% Revenue Interest: 84% 18% IRR Note: Assuming a 7.8 Bcf well, with a 6,000 lateral and 40 frac stages Note: Assumes $4/MMBtu realized natural gas pricing Seneca Advantage #1 Fee Ownership Position 28% IRR Seneca Advantage #2 Contiguous Acreage for Multiple Pads 29% IRR Seneca Advantage Fee Ownership + Contiguous Acreage 43% IRR Competitor Advantage #1 Advantage #2 Seneca Advantage Capital Expenditures $9,000 $9,000 $7,000 $7,000 Multiple Pads No No Yes Yes Working Interest 100% 100% 100% 100% Revenue Interest 84% 100% 84% 100% IRR 18% 28% 29% 43% 28

29 Analyst Day - November 2013 Upstream Seneca s Operations Best-In-Class Operator in Lycoming County (EDA) Average Production per Well (MMcf per Day) Seneca Co. 2 Co. 3 Co. 4 Co. 5 Co. 6 Co. 7 Co. 8 Co. 9 Source: DEP Production Data (January 2013 to June 2013) Average MMcf per Day Horizontal Well Count Horizontal Well Count 29

30 Analyst Day - November 2013 Upstream Seneca s Operations Top-Notch Lycoming Economics EUR (Bcfe) Source: ITG IR, raw data provided by didesktop and state agencies Lycoming County: EURs & Breakeven Prices 6.6 EUR (Bcfe) 6.3 Breakeven Price NFG APC SWN RRC XCO $6 $4 $2 $0 Breakeven Price ($/Mcfe) 30

31 Analyst Day - November 2013 Upstream Seneca s Operations Seneca s Lycoming Economics are in the Top 3 Breakeven NYMEX ($/Mcf) $5.00 $4.00 $3.00 $2.00 $2.41 $2.79 $2.80 $2.95 $2.95 Source: ITG IR, raw data provided by didesktop and state agencies Top Marcellus Breakevens by Operator & County (Source: ITG Investment Research) $2.96 $3.03 $3.06 $3.09 $3.11 $3.21 $3.23 $3.25 There are an additional 109 breakeven data points greater than $3.69/Mcf $3.33 $3.35 $3.46 $3.54 $3.62 $3.65 $

32 Analyst Day - November 2013 Upstream Seneca s Operations Driving Down Well Costs Total Well Costs ($ Millions) $12.0 $9.0 $6.0 $3.0 $0.0 In 2014, total well costs are expected to be ~35-40% lower than 2012 $10.0 DCNR Tract 100 Total Well Costs RCS Well Normalized for 5,500 Lateral & 37 RCS Stages $8.1 $6.7 $ (Est.) Best YTD Fiscal Year Tract 100 (EDA) 32

33 Analyst Day - November 2013 Upstream Seneca s Gathering & Marketing Seneca s Overall Marketing Strategy Develop gathering infrastructure with NFG Midstream Historical Strategy Firm sales at interstate pipeline interconnects Current/Long-Term Strategy Firm transport (FT) to major markets Firm sales tied to FT contracts Financial hedges to lock in benchmark and basis risk Financial hedges to lock in benchmark and basis risk 33

34 Analyst Day - November 2013 Upstream National Fuel s Financial Stability Ability to Withstand Pricing Challenges Strong Balance Sheet & Liquidity Position Cash Generation from California Oil No Near-Term Debt Maturities Active Hedging Program 34

35 Analyst Day - November 2013 Upstream Marcellus Shale Factors for Success Acreage Position Quantity & Quality Operating Expertise Control costs Maximize production Gathering, Transportation and Marketing Financial Stability Ability to withstand price swings and market dislocations 35

36 Analyst Day - November 2013 Upstream California Outstanding Cash Flow (1) $ Millions $250 $200 $150 $100 $50 $0 Capital Expenditures Adjusted EBITDA $171.6 $31.4 $27.6 $187.8 $187.6 $47.4 $226.9 $62.9 $215.0 $ Fiscal Year (1) Adjusted EBITDA and Capital Expenditures represent Seneca Resources Corporation s West Division, which includes its activity in Kansas 36

37 Analyst Day - November 2013 Upstream California Looking Back at the Successful Ivanhoe Acquisition Gross Prodcution (BOPD) 1,600 1,400 1,200 1, Seneca South Midway Sunset Production SRC Development Production Purchase Price $39.2 million Proved PV-10 at 9/30/13 (1) $149.5 million $10.3 million cumulative net cash flow (including purchase price) since acquisition (1) PV-10 from 10/1/2013 SEC reserves Acquisition Date Historical PDP (Assumes 6% Decline) Cash Flow ($ Millions) $60 $45 $30 $15 $0 ($15) ($30) ($45) Annual Cumulative $2.6 $3.4 Net Production at Acquisition 550 Bbl per Day (March 2009) Net Production at 9/30/13 1,157 Bbl per Day 110% Increase Ivanhoe Acquisition Cash Flow $10.9 $11.4 $25.6 $27.6 7/1/ Est. Fiscal Year 37

38 Analyst Day - November 2013 Upstream California Looking Forward 1. Manage decline of base production 2. Pursue and develop opportunities for growth from current assets Sespe East Coalinga South Midway Sunset 3. Continue to pursue additional acquisition and farm-in opportunities 38

39 Analyst Day - November 2013 Upstream Seneca Resources Key Metrics Operational Strategy Focus on growthoriented Marcellus Shale assets with significant fee acreage Maintain and grow strong cash flow assets in California Metric Fiscal 2009 East Division Production East Division Proved Reserves East Division EBITDA Operating Costs (1) West Division EBITDA Cash Margin (2) (1) Defined as LOE and G&A per Mcfe (2) Defined as realized price including the effects of hedging less LOE, G&A and production taxes 9 Bcfe (21% of Total Production) 152 Bcfe (29% of Proved Reserves) $57 million (20% of Total EBITDA) $2.15 per Mcfe $172 million $52 per Bbl Strategic Improvements 12x Production Growth 7x Reserve Growth 5x EBITDA Growth 49% Decrease per Mcfe 25% EBITDA Growth 28% Margin Improvement Fiscal Bcfe (83% of Total Production) 1,240 Bcfe (80% of Proved Reserves) $284 million (57% of Total EBITDA) $1.09 per Mcfe One of the lowest cost producers in the region $215 million $66 per Bbl 39

40 Analyst Day - November 2013 Upstream Seneca Resources What Will Seneca Look Like Moving Forward? Consistent Production Growth: 15-25% CAGR Driven by a very large, high-quality Appalachian acreage position Disciplined Spending Driven by Rates of Return Pace of development adapts to changing market dynamics Maintain Oil Production Expand When Possible Excellent operator and significant cash flow generation A Leader in Technology, Safety & Environmental Responsibility Maintain a leadership role in using technology and developing best practices 40

41 Analyst Day - November 2013 Upstream Appraisal & Development Overview 41

42 Analyst Day - November 2013 Upstream Marcellus Shale WDA Is the Key to Seneca s Long-Term Growth Outlook Seneca Fee Seneca Lease 720,000 Acres 60,000 Acres Full Development Started in ,700 to 2,000 locations de-risked Long-term driver of growth Full Development Since 2010 ~225 locations remaining wells in Lycoming County Near-term driver of growth 42

43 Analyst Day - November 2013 Upstream Marcellus Shale Significantly Improved Understanding of the WDA SRC Fee Acreage SRC Lease Acreage 3D Seismic Outlines EOG Earned Acreage Tionesta Key Statistics Vertical Wells: 30 Full Core: 8 Sidewall Core: 2 3D Seismic: 432 sq m Owl s Nest Church Run James City Sulger Farm Ridgway Mt. Jewett St. Mary s Clermont Boone Mtn Red Hill/ Leasgang Kyler s Corner Punxy W. Branch Rich Valley Beechwood 43

44 Analyst Day - November 2013 Upstream Marcellus Shale Northwest PA Generalized Cross-Section CaCO 3 TOC Owl s Nest James City Platform Ridgway High organics, great rock quality, less variability Rich Valley Clermont Transitional Outer Shelf Beechwood Leasgang High variability, very poor rock quality in areas Basin Punxy Sed. Rate Medium rock quality, high pressures 44

45 Analyst Day - November 2013 Upstream Marcellus Shale WDA Log Summary Cross-Section TOC/PHI/BWV 0 Wt% v/v v/v 0 Mineralogy Volume % ɸ = % Total GIP = ~70/sect Gas Resource 0 Mcf/ac-ft Bcf/mi 100 Platform TOC/PHI/BWV 0 Wt% v/v v/v 0 Mineralogy Volume % Gas Resource 0 Mcf/ac-ft Bcf/mi 100 ɸ = % Total GIP = ~75/sect TOC/PHI/BWV 0 Wt% v/v v/v 0 Transitional Outer Shelf Mineralogy Volume % Gas Resource 0 Mcf/ac-ft Bcf/mi 100 Very poor rock quality. Low gas in place. ɸ = % Total GIP = < 40/sect TOC/PHI/BWV 0 Wt% v/v v/v 0 Basin Mineralogy Volume % ɸ = % Total GIP = ~60/sect Gas Resource 0 Mcf/ac-ft Bcf/mi

46 Analyst Day - November 2013 Upstream Marcellus Shale 2013 & 2014 WDA Delineation Program SRC Fee Acreage SRC Lease Acreage EOG Earned JV Acreage Tionesta Delineating 1 Well Completed Seneca Operated Church Run Delineating 1 Well Completed Heath Delineating 1 Well Planned Clermont Full Development 2 Wells Completed 9H: 7-Day IP of 10 MMcf/d & EUR of 8.6 Bcf 10H: 7-Day IP of 7.4 MMcf/d & EUR of 6.6 Bcf Owl s Nest Delineating 2 High Btu Wells Completed Sulger Farms Delineating 1 Well Planned Rich Valley Full Development 2 Wells Completed 7-Day IP of 7.8 MMcf/d & EUR of 7.4 Bcf 2 nd Well 7-Day IP: 4.5 MMcf/d Hemlock Delineating 1 Well Planned Ridgway Delineating 1 Well Completed 2013 Drill Program 2014 Drill Program 46

47 Analyst Day - November 2013 Upstream Marcellus Shale Rich Valley/Clermont is in Full Development Mode Marcellus Faults Marcellus & Basement Faults Clermont RCS: 9H 7-day IP: 10.0 MMcf/d (EUR: 8.6 Bcf) Non-RCS: 10H 7-day IP: 7.4 MMcf/d Pad H Pad E SRC Fee Acreage SRC Lease Acreage Pad O JV Wells Pad N: Spacing Test Clermont Pad D Rich Valley 7-day IP: 7.8 MMcf/d EUR: 7.4 BCF Lateral Length: 6,372 Rich Valley Rich Valley 2 nd Well 7-day IP: 4.5 MMcf/d Lateral Length: 4, Horizontal Locations 47

48 Analyst Day - November 2013 Upstream Marcellus Shale Clermont Wells Improved from Early Non-Op JV Wells Clermont 5H & 6H (Non-op wells) Avg. lateral length: 3,344 Small casing: 4.5 Restricted pump rates Wide stage spacing: 350 No soaking, low Sw s Clermont 9H & 10H (Seneca wells) Avg. lateral length: >5,500 Large casing: 5.5 Increased pump rates 9H (RCS): 150 spacing 10H (Standard): 240 spacing Soaked both wells: 30 Days Mcf per Day 10,000 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 0 SRC Clermont vs. Non-Op JV Clermont 9H 10H COP H COP H 9H: RCS Completion (150 stage spacing) 10H: Standard Completion (240 stage spacing) Non-Op JV Wells (5H, 6H) Days On 48

49 Analyst Day - November 2013 Upstream Marcellus Shale Moving All Completions to Reduced Cluster Spacing (RCS) 300 Fracture RCS Design ~1000 Wellbore Formation Twice the number of stages/perforations Increases stimulated reservoir volume 300 Conventional Design Fracture ~1000 Wellbore Increased proppant near the wellbore improves fracture conductivity Formation 49

50 Analyst Day - November 2013 Upstream Marcellus Shale Consistently Improved Results in the Owl s Nest Area 2013 Appraisal Program Lateral length >4,400 to 6,200 RCS completions 150 spacing Soaked wells days Target interval Union Springs: 100% in target Flowback Gas Rate (Mcfd) 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 0 Ridgway Owl s Nest Church Run Elapsed Time Owl s Nest Area Ridgway Church Run ON1H-Sales ON3H-Sales ON54H 50

51 Analyst Day - November 2013 Upstream Marcellus Shale Strong Wells Across WDA Acreage Well Name Completion Design Treatable Lateral Length Stages Peak 24-Hour Rate (MMcfd) Peak 7-Day Rate (MMcfd) EUR (Bcf) Status Rich Valley 27H RCS 1 6, Producing Clermont 9H RCS 5, Producing Clermont 10H Non-RCS 5, Producing Ridgway 19H RCS 5, Church Run 2H RCS 4, Owl s Nest 54H RCS 6, Owl s Nest 59H RCS; Gel 2 5, (1) RCS Reduced Cluster Spacing (2) Completed using linear gel to place larger proppant near the wellbore Flowback Test Flowback Test Flowback Test Flowback Test 51

52 Analyst Day - November 2013 Upstream Marcellus Shale Key Areas of Improvement in Recent Delineation Program Areas of Improvement Target Selection (Landing Depth) Target Execution Completion Design Lateral Length Delineation Program Identification of specific target interval is key Percent of wellbore in target interval increased from prior years Reduced Cluster Spacing (RCS) Shorter stages: From down to 150 Increased volume of sand per foot Drilled laterals 15-45% longer than in prior years 52

53 Analyst Day - November 2013 Upstream Marcellus Shale Selection of Target Interval is Critical Percent In Current Target (% of CLL) 100% 75% 50% 25% Wells Averages Percentage of Wellbore in Current Target Interval 23% 33% 0% Well Year 83% 260% Improvement Previous programs spent a significant portion ( > 60% ) of the wellbore outside of the current target interval, identified to have improved productivity 53

54 Analyst Day - November 2013 Upstream Marcellus Shale Optimized Landing Depth EDA Lycoming Type Log Improved Target Zone Drivers Best rock quality in terms of organic content, brittleness, and porosity Highest rate of penetration (ROP) ROP vs Height Above Onondaga ROP (ft/hr)

55 Analyst Day - November 2013 Upstream Marcellus Shale Continued Improvement Staying within Targeted Interval Percent In Target (% of CLL) 100% 75% 50% 25% Wells Averages Percent of Wellbore In Target Zone (15-20 Interval) 71% 69% 0% Well Year Reasons for Improvement 83% 17% Improvement 3D seismic acquisition Improved communication between Geology, Drilling and Completion teams Geosteering technology (azimuthal GR) 55

56 Analyst Day - November 2013 Upstream Marcellus Shale RCS & Increased Sand Volume Generating Better Results Avg. Stage Spacing per Foot Increases near wellbore fracturing & stimulated reservoir volume Stage Spacing & Count Well Year Wells Averages Stage Count Stage Count Pounds of Sand per Foot 1,700 1,600 1,500 1,400 1,300 Improved near wellbore fracture conductivity Pounds of Sand per Foot 1,275 1,448 1,479 1, Wells Well Year Averages Reducing stage length, increasing the number of stages, and increasing proppant volume have been integral in improving well productivity 56

57 Analyst Day - November 2013 Upstream Marcellus Shale Longer Laterals Drive Improved Economics Completed Lateral Length (ft) 7,000 6,000 5,000 4,000 3,000 Wells Averages 3,709 Completed Lateral Length (ft) 4,838 5,586 2, Well Year Lateral lengths have increased even as target selection and execution have improved 50% Increase 57

58 Analyst Day - November 2013 Upstream Marcellus Shale 2013 Appraisal Program was a Success P P P P30 P P50 P P P80 P hr Flowback Rate (Mcf/d/1000') P10 P50 P90 Mean StDev FY13 Program 1,427 1, , Previous Programs 1, Program P Avg Rate, Peak 50 hr/1000' 95% improvement 2013 Program Rich Valley Flowback EUR: 7.4 BCF 58

59 Analyst Day - November 2013 Upstream Marcellus Shale 200,000 Acres With 6-8 Bcfe EUR Wells SRC Fee Acreage SRC Lease Acreage EOG Earned JV Acreage 2014 Hz Appraisal Program Locations Note: Assumes 6,000 treated lateral length 4-6 BCF/well 6-8 BCF/well 4-6 BCF/well 2-4 BCF/well 2-4 BCF/well Vertical well data base 59

60 Analyst Day - November 2013 Upstream Marcellus Shale 1,700 To 2,000 Economic WDA Locations Below $4/Mcfe Prospect County Product Approx. Remaining Locations EUR (Bcfe) BTU IRR $4/MMBtu 15% IRR (1) Breakeven Price ($/Mcf) Tract 100 Lycoming Dry Gas ,030 90% $2.20 Gamble Lycoming Dry Gas ,030 77% $2.33 Tract 595 Tioga Dry Gas ,030 45% $2.63 Clermont/Rich Valley Elk/Cameron Dry Gas ,050 38% $2.80 Ridgway Elk Dry Gas ,111 26% $3.30 Hemlock Elk Dry Gas ,070 23% $3.40 Church Run Elk Dry Gas ,125 22% $3.45 (W) West Branch McKean Dry Gas ,050 22% $3.48 Covington Tioga Dry Gas Developed 5.7 1,030 22% $3.49 Heath Jefferson Dry Gas ,060 19% $3.65 Sulger Farms Jefferson Dry Gas ,020 19% $3.66 Owl s Nest/James City Elk/Forest Dry Gas ,125 18% $3.69 Boone Mt. Elk Dry Gas ,020 18% $3.76 Church Run Elk Wet Gas ,140 13% $4.32 Tionesta Forest/Venango Wet Gas/ Liquids ,325 12% $4.50 Owl s Nest/James City Elk/Forest Wet Gas ,140 11% $4.51 Mt. Jewett McKean Wet Gas ,140 6% $5.50 Beechwood Cameron Dry Gas ,030 2% $7.14 Red Hill Cameron Dry Gas ,030 2% $ Appraisal prospects 2014 Appraisal prospects (1) Internal Rate of Return (IRR) includes estimated well costs, LOE, and Gathering tariffs anticipated for each prospect 60

61 Analyst Day - November 2013 Upstream Marcellus Shale Marketing Intercompany Gathering Ensures Timely Gas Sales Develop gathering infrastructure with NFG Midstream Historical Strategy Firm sales at interstate pipeline interconnects Current/Long-Term Strategy Firm transport (FT) to major markets Firm sales tied to FT contracts Financial hedges to lock in benchmark and basis risk Financial hedges to lock in benchmark and basis risk 61

62 Analyst Day - November 2013 Upstream Marcellus Shale Marketing Securing Firm Transportation to Major Markets Current Seneca Development Areas Firm transport to Canada, Northeast and Southeast U.S. markets 62

63 Analyst Day - November 2013 Upstream Marcellus Shale Marketing TGP 300 Production & Firm Sales Aligned Thru 2014 Gross MMBtu per Day Dawn NYMEX Dominion Production (Forecast) NYMEX Index Less $0.24 Dominion Index Less $0.37 Dawn Index Less $

64 Analyst Day - November 2013 Upstream Marcellus Shale Marketing Targeting Future Firm Sales on Transco Gross MMBtu per Day Transco Z6 NY/NNY NYMEX Dominion Production (Forecast) NYMEX Index Less $0.29 Dominion Index Less $0.14 Transco Zone 6 Index Less $

65 Analyst Day - November 2013 Upstream Point Pleasant & Utica Shale Continuing to Delineate Permitted Drilled/Drilling Completed Producing Halcon 2.5 MMcf/d, 360 Bbls/d Halcon 4.5 MMcf/d, 860 Bbls/d Range Resources 1.4 MMcf/d Not Effectively Stimulated Chesapeake 6.4 MMcf/d Range Resources 4.4 MMcf/d Eastern Ohio Point Pleasant Core Rex 9.2 MMcf/d Halcon 6.6 MMcf/d, 750 Bbls/d Point Pleasant Northern Boundary Mt. Jewett Horizontal: completed September 2013 Peak 24-Hour Rate: 8.5 MMcf/d Tionesta Horizontal: Completed Fall 2012 Peak 24-Hour Rate: 3.9 MMcf/d 65

66 Analyst Day - November 2013 Upstream Mississippian Lime Commencing Evaluation Program in Fiscal 2014 Total Net Acres: 13, % working interest in 4,400 gross acres 55% net working interest in 17,365 gross acres Negotiated an increase in Seneca s working interest and have taken over as operator Currently drilling first well Will drill up to 5 evaluation wells in 2014 Unit 30-day IP: 352 BOED (92% Oil/NGLs) The initial entry into the Mississippian Lime play furthers the Company s goal of maintaining a significant contribution from oil-producing properties 66

67 Analyst Day - November 2013 Upstream California Update 67

68 Analyst Day - November 2013 Upstream California Stable Production Fields; Modest Growth Potential East Coalinga Temblor Formation Primary North Lost Hills Tulare & Etchegoin Formation Primary/Steamflood South Lost Hills Monterey Shale Primary North Midway Sunset Tulare & Potter Formation Steamflood Gross Operated Daily Production (Boe/d) South Midway Sunset Antelope Formation Steamflood 6,000 4,500 3,000 1, ,500 4,000 North Midway Sunset 500 1,200 South Midway Sunset 1,700 1,500 South Lost Hills 1,200 1,100 North Lost Hills 800 1,100 Sespe Key Areas of Focus in East Coalinga Evaluation 2. South Midway Sunset Extensions 3. Sespe Coldwater Evaluation Sespe Sespe Formation Primary East Coalinga 68

69 Analyst Day - November 2013 Upstream California South Midway Sunset Has Delivered Significant Growth B Pool 16X Pool 1000 Existing Wells A Pool 251 Pool Original Pool Boundary Extended Pool Boundary 97X Pool SE Pool 252 Pool Daily Production (Boe per day) 2,000 1,500 1, Monthly Production at South Midway Sunset Seneca Acquired in June 2009 Highlights Since Acquisition Increased daily production by 130% Drilled 80 new producers Added 3.3 MMBO of proven reserves Increased steam capacity by 280% Identified opportunities for additional pool development 69

70 Analyst Day - November 2013 Upstream California South MWSS Growth Opportunities Continue into

71 Analyst Day - November 2013 Upstream California Early Success in Farm-In with Chevron at East Coalinga Returned to Production 2013 Evaluation Wells Seneca Lease Existing Wells Downspacing Potential acre (~30 locations) 2-acre (~40 locations) 5-acre (~120 locations) 2-Acre Test 18 BOPD 5-Acre Test 54 BOPD 1-Acre Test 48 BOPD Daily Production (Boe per Day) Monthly East Coalinga Seneca Acquired in January 2013 Highlights Since Acquisition Achieved highest field production in 10 years Production increased 130% since 1/2013 Drilled 12 evaluation wells that confirmed downspacing potential Returned 40 idle wells back to production 71

72 Analyst Day - November 2013 Upstream California Ramping Up the Coalinga Drill Program in Fiscal Development Program (Tentative) 2014 Locations (30) 2013 Locations (12) Location Selection Criteria 2013 new well production Reservoir pressure mapping Historical production Past EOR attempts 72

73 Analyst Day - November 2013 Upstream California Ongoing Evaluation of Long-Term Sespe Potential 2011 Wells (5) 2012 Wells (6) 2013 Wells (6) 2014 Wells (4) X SANDS ISOCHORE (Thickness) WS st Oil in 11/13 WS st Oil in 11/13 TC IP: 100 BOEPD 1 st Oil 10/13 TC IP: 160 BOEPD 1 st Oil 10/13 Year Target 1 Mile # of Wells Average IP (BOEPD) 2011 Sespe (5-Acre Infill) Sespe (10-Acre) Sespe (5-Acre Infill) Coldwater Sespe (10 Acre) Sespe (5-Acre Infill) 2 NA 2013 Coldwater Sespe (10 Acre)

74 Analyst Day - November 2013 Upstream California Evaluating the Monterey Shale at South Lost Hills Upper Antelope A Upper Antelope B McDonald GR SP Lower Reef Ridge Citrus 11 Brittleness ResD Oil Gas Truman 2H Planned FY14 Truman 1H BOEPD Citrus 2H Planned FY14 18 potential locations in each of the three horizons (concept) Seneca Lease

75 Analyst Day - November 2013 Upstream California Limited Growth Opportunities, But Strong Economics Field Average Well Cost Average EUR (MBO) Estimated Fiscal 2014 Locations South Midway Sunset $250, % 23 East Coalinga $400, % 30 Sespe 5 Acre Infill $2,800, % 0 Sespe - Coldwater $2,800, % 4 75

76 Analyst Day - November 2013 Upstream California Modest Growth Anticipated in 2014 and 2015 Average Daily Net Production (BOE per Day) 10,000 9,000 8,000 7,000 6,000 9,056 8,773 9,322 9, (Est.) 2015 (Est.) Fiscal Year Forecast 76

77 Analyst Day - November 2013 Upstream Marcellus Operational & Environmental Overview 77

78 Analyst Day - November 2013 Upstream Marcellus Shale Our Development Approach Drives Major Efficiencies Multi-Well Pads Focused Development Areas Technical & Operational Expertise Faster Spud-to-Sales Timing Economies of Scale Reduces Costs Minimal Infrastructure Constraints & Well Backlog 78

79 Analyst Day - November 2013 Upstream Marcellus Shale EDA Delivering Significant Growth DCNR Tract 595 Gross Production: ~100 MMcf per Day 34 Wells Drilled (52 Total Locations) 26 Wells Producing DCNR Tract 100 Gross Production: ~220 MMcf per Day 40 Wells Drilled (70 Total Locations) 30 Wells Producing Covington Fully Developed Gross Production: ~60 MMcf per Day 47 Wells Drilled and Producing Gamble Recently, 30 to 50 future locations were added in Lycoming County 79

80 Analyst Day - November 2013 Upstream Marcellus Shale EDA Historical Well Results Are Exceptional Development Area Covington Tioga County Tract 595 Tioga County Tract 100 Lycoming County Producing Well Count Average IP Rate (MMcf/d) Average 7-Day (MMcf/d) Average 30-Day (MMcf/d) Average EUR per Well (Bcf) Average Lateral Length EUR per 1,000 of Lateral (Bcfe) , , , Seneca s acreage in Lycoming County has consistently delivered some of the most prolific wells in the Marcellus Shale 80

81 Analyst Day - November 2013 Upstream Marcellus Shale Faster Spud-to-Sales: Drilling Efficiencies Daily Footage 1,500 1, DCNR Tract 100 (Lycoming) Average Daily Drilling Footage , Q4 Fiscal Year 1, (Est.) 1,320 Best FYTD How has this been accomplished? Directional Plan Optimization Minimize drilling path corrections Bit Selection Increases drilling rate and durability Drill Top-hole Sections Deeper with Water More efficient and cost effective Optimize Landing Depth Improves production and rate of penetration 81

82 Analyst Day - November 2013 Upstream Marcellus Shale Faster Spud-to-Sales: Multi-Well Pads Are Key Rig Moves Average Number of Yearly Rig Moves Average Rig Moves (per Rig) Wells per Pad Limiting the movement of rigs between pads allows for more drilling Using LEAN practices has eliminated four days from each rig move Staying in smaller regional areas further limits move time Wells per Year Average Wells per Year (per Rig) Average per Well Move Cost ($ Thousands) $500 $400 $300 $200 $100 $0 Average Rig Move Cost per Well $390 $2.6 $225 $4.0 $143 $4.6 $115 $4.8 $ Average per Well Move Cost Wells per Pad $6.0 $5.0 $4.0 $3.0 $2.0 $1.0 $0.0 Cumulative Annual Cost Savings ($ Millions) Average Savings per Year (per Rig) 82

83 Analyst Day - November 2013 Upstream Marcellus Shale Drilling Efficiencies Allow for More Wells per Year Wells per Rig per Year ,929 Drilling Efficiency vs. Lateral Length All Marcellus Wells 4,614 4, , , (Est.) Fiscal Year In spite of increasing the average lateral length, each rig is drilling more wells per year 6,000 4,000 2,000 0 Average Lateral Length (Feet) 83

84 Analyst Day - November 2013 Upstream Marcellus Shale Faster Spud-to-Sales: Completing More Stages per Day How has this been accomplished? Completion Efficiency Technologies Hydraulic toe sleeves, frac sleeves, Lean fundamentals (NPT tracking) 24-Hour Operations Double the stages per day Water Pipelines More efficient than trucking water RCS Stages per Day DCNR Tract 100 (Lycoming) RCS Stages per Day Q1 Fiscal Year (Est.) 84

85 Analyst Day - November 2013 Upstream Marcellus Shale Faster Spud-to-Sales: The Overall Picture (Est.) (1) (1) 2010 completion time based on a 5-well pad normalized to a 6-well pad Average Spud-to-Sales for a 6-Well Pad (Normalized for 5,500 Laterals per Well) Drilling Days Completion Days 226 Days 253 Days 259 Days 85

86 Analyst Day - November 2013 Upstream Marcellus Shale Faster Spud-to-Sales: More Lateral Feet Completed Yearly Stages Completed 2,000 1,500 1, Stages per Year (RCS) Stages per Year (Non-RCS) Lateral Feet Completed Total Lateral Feet & Stages Completed ,298 1, ,888 1, Fiscal Year (Est.) Lateral Feet Completed (Thousands) 86

87 Analyst Day - November 2013 Upstream Marcellus Shale Drilling Cost Reductions: Several Contributing Factors Drilling Days DCNR Tract 100 (Lycoming) Average Drilling Days to TD (Normalized for a 5,500 Treatable Lateral) Q4 Fiscal Year (Est.) Best FYTD $5.0 $4.0 $3.0 $2.0 $1.0 $0.0 Improvements From 2012 to 2013 ($525,000 per well) Shorter drilling days to TD: $300,000 Drilling Cost ($ Millions) DCNR Tract 100 (Lycoming) Average Drilling Cost (Normalized for a 5,500 Treatable Lateral) $4.4 $3.8 $3.3 $ Q4 Fiscal Year Faster rig moves (2012: 8.5 Days 2013: 4.5 Days): $20,000 (6-well pad) Procurement and supply chain initiatives: $120,000 Directional plan optimization: $60,000 Natural gas-powered rigs: $25,000 $ (Est.) $2.0 Best FYTD 87

88 Analyst Day - November 2013 Upstream Marcellus Shale Completion Cost Reductions: Ongoing Optimization Completion Costs per Stage ($ Thousands) $200 $150 $100 $50 $0 DCNR Tract 100 (Lycoming) Average RCS Completion Cost per Stage $160 $131 $ (Est.) Fiscal Year $113 Best FYTD How is this being accomplished? New Frac Contract in 2014 Pumping, sand and chemical costs reduced ~20% Savings: $10,000/stage Completion Efficiencies 24-hour operations New technologies Savings: $5,000/stage Water Infrastructure Full trucking: $7.00/Bbl Limited trucking: $ $3.00/Bbl Savings: $25,000/stage 88

89 Analyst Day - November 2013 Upstream Marcellus Shale Completion Cost Reductions: New Efficient Technologies Prep Frac Drill-Out Time Savings 4 days per well 24 days per 6-well pad Time Savings 6 days per well 36 days per 6-well pad Time Savings 5 days per well 30 days per 6-well pad Toe Sub $60,000 savings per well Sleeve $200,000 savings per well Dissolvable Balls $300,000 savings per well $3.4 million saved on a 6-well pad from the utilization of new technologies 89

90 Analyst Day - November 2013 Upstream Marcellus Shale Completion Cost Reductions: Water Infrastructure Water Pipeline Storage Impoundment System Cost: $8.5 million 8 miles of pipeline 43 million gallons of storage Will serve at least 70 wells Provides 75% of water needs, with the remainder being recycled production fluid Environmental & Cost Benefits Eliminated the need for 47,000 water trucks since February 2012 Saved more than $4 million on Tract 100 development to date Improved Efficiencies Trucking in water across this challenging terrain would have delayed completions and production This model has been successful in Lycoming & Tioga counties and will be utilized in the WDA as development progresses 90

91 Analyst Day - November 2013 Upstream Marcellus Shale Minimizing Backlogs: Coordinated Development Sales Lag (Months) IRR $4/Mcf Realized Pricing 90% 58% 46% 38% Coordination with NFG Midstream to construct gathering systems Development well backlog typically consists of wells on pads in either the drill or complete phase Regional development programs Focus on multi-well pads in smaller geographic areas allows for efficient gathering connectivity Managing completion schedule Ongoing monitoring of operations and maintaining the flexibility to alter completion schedules (1) Assumes 6,000 completed lateral length, $7.5MM well cost, and 11.5 Bcf EUR 91

92 Analyst Day - November 2013 Upstream Seneca Resources Committed to Health, Safety, and the Environment Seneca Resources Corporation Value Statement We ask that each employee share in our philosophy and unwavering commitment to each other s health and safety and the environment. Dedicated 24-Hour EHS Hotline and Address Best Practices Incorporating Lean Process Strategies Management team dedicated to building a culture of continual EHS improvement creating a systematically integrated model of EHS stewardship beyond mere compliance. Operating Excellence Program Compliance Department 92

93 Analyst Day - November 2013 Midstream Midstream Businesses Overview 93

94 Analyst Day - November 2013 Midstream Midstream Businesses National Fuel s Midstream Businesses Pipeline & Storage Segment NFG Midstream Businesses National Fuel Gas Supply Corporation Empire Pipeline, Inc. Gathering Segment National Fuel Gas Midstream Corporation Reporting Segments Subsidiaries 94

95 Analyst Day - November 2013 Midstream Midstream Businesses Positioned Well to Serve Appalachian Producers Mercer (TGP) Niagara(TCPL) NFG NFG Holbrook (TETCO) Major Interconnects East Aurora (TGP/DTI) Independence (Millennium) Ellisburg (TGP 300) Leidy (Transco/TETCO) National Fuel Gas Supply Corporation System Length Storage Capacity Contracted Transport ~ 2,550 Miles 73.4 Bcf 2.58 MMDth/d 2013 Revenue $191.2 Million Capital Expenditures $304.6 Million 95

96 Analyst Day - November 2013 Midstream Midstream Businesses Positioned Well to Serve Appalachian Producers Chippawa (TCPL) Major Interconnects Mendon (RG&E) Lysander Sithe Hopewell (TGP 200) Corning (Millennium) Jackson (Shell/Talisman) System Length Empire Pipeline Contracted Transport ~250 Miles 1.07 MMDth/d 2013 Revenue $76.4 Million Capital Expenditures $62.8 Million 96

97 Analyst Day - November 2013 Midstream Midstream Businesses Positioned Well to Serve Appalachian Producers Major Interconnects TGP 300 Transco NFG Midstream Corp. System Length 59 Miles 2013 Revenue $34.8 Million Capital Expenditures (Since Inception) $168 Million 97

98 Analyst Day - November 2013 Midstream Midstream Businesses Long-Term Strategy Driven by Both Seneca & 3 rd Parties Develop strong partnerships with customers to help them reach diverse, high-value markets Seneca Resources Midstream Businesses Diverse Markets 3 rd Party Shippers 98

99 Analyst Day - November 2013 Midstream Midstream Businesses Positioned to Serve Seneca s Rapidly Growing Production 99

100 Analyst Day - November 2013 Midstream Gathering Gathering is the Crucial First Step to Reaching a Market Gathering Interconnects (In-Service and Under Construction) Clermont Gathering System (Under Construction) Covington Gathering System (In-Service) TGP 200 TGP 300 Trout Run Gathering System (In-Service) Transco 100

101 Analyst Day - November 2013 Midstream Gathering Existing Systems Supporting Seneca s Near-Term Growth Covington Gathering System In-service date: November 2009 Capacity: 220,000 Dth per day Interconnect: TGP 300 Capital expenditures (to date): $28.3 million Capital expenditures (future): $7.5 million Trout Run Gathering System In-service date: May 2012 Capacity: 466,000 to 585,000 Dth per day Interconnect: Transco Leidy Lateral Capital expenditures (to date): $128.0 million Capital expenditures (future): $60 to $90 million $ Millions $100 $75 $50 $25 $0 Fiscal Year Revenue by Project (Covington & Trout Run Systems) $14 $2 $16 $17 $15-$17 $41-$ (Est.) Covington Trout Run Total Throughput Throughput (MMDth) Interconnects 101

102 Analyst Day - November 2013 Midstream Gathering Developing a 1+ Bcf/d Gathering System in the WDA C Compressor Station Interconnect Plan to expand ahead of Seneca s development to provide natural gas as rig fuel C Clermont 2014 Expansion In-Service: August 2014 Initial Trunkline Capacity: 700 MMcf per day Interconnect TGP 300 Total Cost: $60-$92 Million Major Facilities 24 Pipeline 6 Miles 8-20 Pipeline 25+ Miles Seneca Pads Producing 2 in Fiscal 2014 (15 Wells) 102

103 Analyst Day - November 2013 Midstream Gathering Clermont Gathering System has Large Expandability C C Compressor Station Interconnect C C C Clermont 2015 Expansion In-Service: Ongoing build-out Ultimate Trunkline Capacity: 700 to 1,000 MMcf per day Interconnects TGP 300 and National Fuel Gas Supply Corporation (anticipated) Total Cost: $75 - $125 million Major Facilities Additional Gathering Clermont West, Clermont East and Rich Valley Compressor Stations Seneca Pads Connected Up to 25 pads connected following the 2015 expansion 103

104 Analyst Day - November 2013 Midstream Gathering A Number of Options to Serve 3 rd Party Producers C C Compressor Station Interconnect C C Midstream is evaluating a number of trunkline and gathering line expansions in fiscal 2015 and beyond, depending on Seneca activity and third-party producer interest C 104

105 Analyst Day - November 2013 Midstream Gathering 2014 Spending Driven by Seneca Development 28% 2014 Forecast Capital Expenditures 6% 6% 60% $100 to $150 Million Clermont - $60 MM - $92 MM Build 30+ miles 24 and smaller diameter pipe Procure 10 compressor units for Phase I Upgrade existing interconnect into TGP Trout Run - $30 MM - $40 MM Complete two compressor stations (Total = 15 units) Initiate build out of Gamble Prospect gathering, south of DCNR Tract 100 Covington - $6 MM - $9 MM Build gathering for 3 additional well pads at DCNR Tract 595 Other Seneca WDA Prospects - $4 MM - $ 9 MM Build gathering and interconnect locations for Church Run and Ridgway prospects 105

106 Analyst Day - November 2013 Midstream Gathering More than 1.5 Bcf per day of Gathering Capacity by 2015 Year-End Gathering Capacity (MMcf per Day) 2,500 2,000 1,500 1, NFG Midstream Gathering Capacity , ,421-1, , Fiscal Year Forecast Covington Trout Run WDA Other Clermont 2015 Forecast 106

107 Analyst Day - November 2013 Midstream Gathering Capital Deployment Will Deliver Long-Term Growth Capital Expenditures ($ Millions) $500 $400 $300 $200 $100 $0 Revenue Cumulative Capital Invested Revenue Growth (2013 to 2015): ~60% CAGR Capital Investment (2013 to 2015): ~60% CAGR $113 $17.5 $168 $34.8 $268-$318 $60-$ Fiscal Year Forecast $368-$468 $80-$ Forecast $150 $120 $90 $60 Revenue ($ Millions) $30 $0 107

108 Analyst Day - November 2013 Midstream Pipeline & Storage Project Opportunities to Support WDA Growth Develop multiple outlets to high-value markets 108

109 Analyst Day - November 2013 Midstream Midstream Businesses Providing Transportation to Higher-Priced Markets Short Supply Currently Short Supply 109

110 Analyst Day - November 2013 Midstream Midstream Businesses NE Supply Approaching NE Peak Demand Northeast Supply (Bcf per Day) Actual Peak Demand (24-25 Bcf per day) Median Demand (11.5 Bcf per day) Forecasted Kentucky New York Ohio Pennsylvania Virginia West Virginia Source: Production Data Bentek Northeast Natural Gas Production Monitor (November 2013); Demand Data TPH Research Supply exceeds demand for 70% of the year by

111 Analyst Day - November 2013 Midstream Midstream Businesses Focusing on Projects to Non-Traditional Demand Markets The markets of Eastern Canada, the Mid-Atlantic and Southeast look to be the most desirable markets for shippers to reach over the long-term Short Supply 111

112 Analyst Day - November 2013 Midstream Pipeline & Storage Delivering Into the Eastern Canadian Market is Valuable $ per MMBtu $1.40 $1.20 $1.00 $0.80 $0.60 $0.40 $0.20 $0.00 Eastern Canada (Dawn) is Currently a Premium Priced Market Dawn to Henry Hub Dawn to Dominion South Point 112

113 Analyst Day - November 2013 Midstream Pipeline & Storage Northeast PA Spot Markets are Heavily Discounted $ per MMBtu $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $0.00 Eastern Canada (Dawn) is Currently a Premium Priced Market Dawn to Dominion South Point Dawn to TGP Zone 4 113

114 Analyst Day - November 2013 Midstream Pipeline & Storage Major Expansion Designed for Canadian Deliveries Canada & Eastern U.S. Delivery Point Niagara (TCPL) Clermont Northern Access 2015 Northern Access 2015 In-Service: November 2015 System: NFG Supply Corp. Capacity: 140,000 Dth per day Interconnect Niagara (TransCanada) Total Cost: $67 Million Major Facilities 23,000 HP Compressor 114

115 Analyst Day - November 2013 Midstream Pipeline & Storage Clermont to Chippawa Provides Delivery Options Clermont to Chippawa In-Service: 2016 System: Supply & Empire Capacity 250,000+ Dth per day Interconnects Corning (Millennium) Hopewell (TGP 200) Chippawa (TransCanada) Total Cost: ~$250 Million Canada & Eastern U.S. Delivery Point Chippawa (TCPL) Clermont Clermont to Chippawa Hopewell (TGP 200) Corning (Millennium) New England New York City 115

116 Analyst Day - November 2013 Midstream Pipeline & Storage Longer-Term: Reaching Markets Along the Atlantic Delivery Point Clermont Transco To Mid-Atlantic & Southeast Clermont to Transco Clermont to Transco In-Service: 2017 System: NFG Supply Corp. Capacity 300,000 to 500,000 Dth per day Interconnect Transco Leidy Line Total Cost: $100 to $150 Million 116

117 Analyst Day - November 2013 Midstream Pipeline & Storage Expansions to Move Gas from the WDA are Significant Projects to Support WDA Growth Project Capacity (Dth/day) Northern Access ,000 Clermont to Chippawa 250,000+ Clermont to Transco 300, ,000 Total New Capacity 690, ,000+ Project Northern Access 2015 Clermont to Chippawa Clermont to Transco Total Capital Expenditures Capital Cost $67 million $250 million $100-$150 million $417-$467 million Northern Access 2015 Clermont Longer-Term WDA Expansion Clermont to Chippawa 117

118 Analyst Day - November 2013 Midstream Pipeline & Storage Seneca Currently Represents a Small Portion of Capacity Non-Affiliate Producer Affiliated LDC Non-Affiliate LDC Non-Affiliate Marketer All Other Affiliated Producer Contracted Transportation Capacity (National Fuel Gas Supply Corp. & Empire Pipeline) 3% 7% 9% Total Contracted Transportation Capacity (at 9/30/13): 3.6 MMDth per Day 21% 29% 31% 118

119 Analyst Day - November 2013 Midstream Pipeline & Storage Recent 3 rd Party Expansions Have Been Highly Successful Northern Access 2013 Line N Projects Tioga County Extension Projects to Support 3 rd Parties Project Capacity (Dth/day) Northern Access ,000 Tioga County Extension 350,000 Line N (2011, 2012 & 2013) 353,000 Total New Capacity 1,023,000 Project Northern Access 2013 Tioga County Extension Line N (2011, 2012 & 2013) Total Capital Expenditures Capital Cost $72 million $58 million $104 million $234 million 119

120 Analyst Day - November 2013 Midstream Pipeline & Storage NFGSC is Now a Net Exporter of Natural Gas to Canada MDth per Day (100) (200) (300) (400) (500) Throughput at the Niagara Delivery Point (Canadian Border) Tennessee Gas Pipeline Northern Access project was placed in-service November 2011 National Fuel Gas Supply Corp. Source: Internal data; TGP Flow Data Bentek Northeast Observer (Monthly Average from June 2011 through October 2013) 120

121 Analyst Day - November 2013 Midstream Pipeline & Storage National Fuel Becoming a Major SW PA Transporter Average Daily Throughput (MDth per Day) All Other Pipes Source: Production Data Bentek Northeast Natural Gas Production Monitor (November 2013) National Fuel Gas Supply Corp. went from no SW Pennsylvania receipts in 2008 to nearly 40% of all volumes today NFGSC 121

122 Analyst Day - November 2013 Midstream Pipeline & Storage Additional Line N Expansions Planned for the Future Mercer (TGP Station 219) Mercer Expansion Mercer Expansion In-Service: November 2014 System: NFG Supply Corp. Capacity: 105,000 Dth per day Precedent agreements signed for all available capacity Interconnect Mercer (TGP Station 219) Total Cost: $30 Million Expansion: $27 million System Modernization: $3 million Major Facilities 3,500 HP Compressor 2.1 miles 24 Replacement Pipeline 122

123 Analyst Day - November 2013 Midstream Pipeline & Storage Pairing Line N Expansions with System Modernization Mercer (TGP Station 219) Holbrook (TETCO) Westside Expansion & Modernization Westside Expansion & Modernization In-Service: November 2015 System: NFG Supply Corp. Capacity: 175,000 Dth per day Precedent agreements signed for 145,000 Dth per day Interconnect Mercer (TGP Station 219) Holbrook (TETCO) Total Cost: $74 Million Expansion: $39 million System Modernization: $35 million Major Facilities 3,600 HP Compressor 23.5 miles 24 Replacement Pipeline 123

124 Analyst Day - November 2013 Midstream Pipeline & Storage Developing Unique Solutions for Shippers Tuscarora Lateral In-Service: November 2015 System: NFG Supply & Empire Pipeline New No-Notice Services Preserving 172,500 Dth per day (RG&E) Preserving 20,000 Dth per day (NYSEG) Precedent agreement executed with RG&E Capacity Transportation: 69,000 Dth per day Retained Storage: 3.3 Bcf Interconnect Tuscarora (NFG/Supply) Total Cost: $56 Million Major Facilities 1,500 HP Compressor 18 miles 20 Replacement Pipeline Tuscarora Lateral 124

125 Analyst Day - November 2013 Midstream Pipeline & Storage Significant Expansions Are Driving Growth Delivering Gas North Tioga County Extension Northern Access Northern Access 2015 Clermont to Chippawa Total Capacity 1,060 MDth/d Line N Corridor Line N Expansion Line N 2012 Expansion Line N 2013 Expansion Mercer Expansion West Side Expansion Total Capacity 603 MDth/d Leaving the WDA Lamont Compressor Clermont to Transco Total Capacity 390 to 590 MDth/d Project Completed Projects Capacity (Dth/day) Lamont Compressor Station 90,000 Line N Expansion 160,000 Tioga County Extension 350,000 Northern Access Expansion 320,000 Line N 2012 Expansion 163,000 Line N 2013 Expansion 30,000 New Capacity Additions 1,113,000 Planned Projects Mercer Expansion Project 105,000 West Side Expansion 145,000 Northern Access ,000 Tuscarora Lateral 69,000 Planned Capacity Additions 459,000 Potential Projects Clermont to Chippawa ~250,000 Clermont to Transco 300, ,000 Potential Capacity Additions 550, ,

126 Analyst Day - November 2013 Midstream Pipeline & Storage Expansion Project Revenue Growth Expansion Project Revenue ($ Millions) $200 $150 $100 $50 $0 $4 $37 Annual Expansion Revenue Projects Placed in Service Since Fiscal 2011 $59 $ (Est.) Fiscal Year $ (Est.) $91 Larger projects under consideration for fiscal 2016 and 2017 will drive significant revenue growth 2016 (Est.) 2017 (Est.) 2018 (Est.) 126

127 Analyst Day - November 2013 Midstream Midstream Businesses New Shale Production Driving Tremendous Growth System Throughput (MDth per Day) 3,000 2,000 1,000 0 Average Daily System Throughput of NFG s Midstream Businesses Doubling From Fiscal 2009 to ,315 1,140 1,301 1,419 2,174 2, Fiscal Year (Est.) Empire Throughput NFGSC Throughput NFG Midstream 2, (Est.) 127

128 Analyst Day - November 2013 Downstream Utility Overview 128

129 Analyst Day - November 2013 Downstream Utility New York & Pennsylvania Service Territories New York Total Customers: 520,000 Rate Mechanisms: Revenue Decoupling Weather Normalization Low Income Rates Choice Program/Purchase of Receivables Merchant Function Charge (Uncollectibles Adjustment) 90/10 Sharing (Large Customers) Natural Gas Vehicle Pilot Program ROE: 9.1% (Litigated ) Pennsylvania Total Customers: 213,000 Rate Mechanisms: Low Income Rates Choice Program/Purchase of Receivables Merchant Function Charge ROE: Black Box Settlement (2007) 129

130 Analyst Day - November 2013 Downstream Utility Customer Usage Usage Per Account (1) (Mcf) Residential Usage 12-Months Ended Sept 30 (1) Weighted Average of New York and Pennsylvania service territories (assumes normal weather) Usage Per Account (1) (MMcf) Industrial Usage 12-Months Ended Sept

131 Analyst Day - November 2013 Downstream Utility Continued Cost Control Helps Provide Earnings Stability O&M Expense ($ Millions) $250 $200 $150 $100 $50 $0 $203 $25 $191 $181 $179 $177 $178 $27 $14 $11 $9 $6 $178 $164 $167 $168 $168 $ Fiscal Year All Other O&M Expenses O&M Uncollectible Expense 131

132 Analyst Day - November 2013 Downstream Utility Capital Spending Largely Focused on Maintenance Capital Expenditures ($ Millions) $100 $80 $60 $40 $20 $0 Capital Expenditures for Safety Total Capital Expenditures $56.2 $58.0 $58.4 $58.3 $44.4 $45.0 $44.3 $43.8 $72.0 $ Forecast Fiscal Year $80-$90 $80-$90 The Utility remains focused on spending to maintain the ongoing safety and reliability of its system 2015 Forecast 132

133 Analyst Day - November 2013 Downstream Utility Providing Predictability and Stability Adjusted EBITDA ($ Millions) $250 $200 $150 $100 $50 $0 The Utility has Delivered Consistent Results $164 $167 $169 $160 $ Fiscal Year Note: A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings is included at the end of this presentation. 133

134 Analyst Day - November 2013 Downstream Utility Working Towards a Settlement in New York March 27, 2013 Filed a plan with the NY PSC to adopt an earnings sharing and stabilization mechanism on earnings above a 9.96% ROE April 19, 2013 NY PSC issued an Order to Show Cause (OTSC) commencing a proceeding to establish temporary rates May 8, 2013 Company responds to OTSC June 1, 2013 OTSC suggests temporary rates could become effective June 14, 2013 Temporary rates become effective July 26, 2013 Settlement discussions commence for permanent rates An agreement in principle has been reached with five parties and the litigation schedule has been extended indefinitely to allow the settlement process to move forward 134

135 Analyst Day - November 2013 Corporate Hedging Overview 135

136 Analyst Day - November 2013 Corporate Hedging Overview How Does Seneca Sell its Production? Well Head Gathering System The 1,700 to 2,000 economic locations at less than $4.00/Mcf are based on a realized price after gathering Interconnection with Interstate Pipeline Network Contracted Basis Differential FT Rate 3rd Party Marketer (or spot market) Spot Market Firm Transport Demand Center (firm sales or spot market) 136

137 Analyst Day - November 2013 Corporate Hedging Overview Firm Sales Provide a Market for Appalachian Production Long-Term Firm Sales (1) (MMBtu per Day) 400, , , ,000 0 Other (Transco) NYMEX Dominion South Point 307,745 NYMEX 202,745 Less: $0.284 Dominion 105,000 Less: $0.265 Winter 2013/2014 Prices shown represent the sales (netback price) at the first non-affiliated interstate pipeline, including the cost of all related downstream transportation. 244,091 NYMEX 149,091 Less: $0.281 Dominion 95,000 Less: $0.305 Summer ,000 NYMEX 150,000 Less: $0.257 Dominion 55,000 Less: $0.236 Winter 2014/2015 (1) Long-term firm sales represent gross volumes 137

138 Analyst Day - November 2013 Corporate Hedging Overview Seneca Methodically Layers in Index Hedges Over Time % Hedged 100% 80% 60% 40% 20% 0% Fiscal 2014 Fiscal 2015 Fiscal 2016 Fiscal 2017 Hedging Policy Range Oil Hedges Natural Gas Hedges Fiscal

139 Analyst Day - November 2013 Corporate Hedging Overview Current Hedge Book has Seneca Positioned Very Well % Hedged 100% 80% 60% 40% 20% 0% 66% Fiscal % 35% Fiscal % 30% Fiscal % 10% Fiscal % Hedging Policy Range Oil Hedges Natural Gas Hedges 3% Fiscal 2018 (1) Hedge positions for fiscal years reflect the midpoint of Seneca s target annual production growth (20%) starting with the midpoint of Fiscal 2015 guidance ( Bcfe) 2% 139

140 Analyst Day - November 2013 Corporate Commodity Risk Management Oil & Natural Gas Hedges are Above the Current Strip (1) Oil Average Hedge Price ($ per Bbl) $ $ $75.00 $50.00 $25.00 $0.00 (1) Data as of November 13, 2013 $94.53 $94.00 $89.81 $88.00 $85.57 $84.00 $4.25 $4.27 $4.35 $4.45 $3.81 $4.07 Crude Oil (Average Hedge Price) Crude Oil (NYMEX Strip) Natural Gas (Average Hedge Price) Natural Gas (NYMEX Strip) $83.12 $81.67 $82.00 $81.00 $4.81 $4.22 $4.34 $ Fiscal Year $10.00 $7.50 $5.00 $2.50 $0.00 Natural Gas Average Hedge Price ($/Mcf) 140

141 Analyst Day - November 2013 Corporate Hedging Overview Determining Seneca s Realized Price on Firm Sales Realized Price = Negotiated at time of Agreement Based on Current Market at Sales/Delivery Point Firm Sales Reference Price + - NYMEX & Dominion Monthly Settlement Prices Basis Differential + - Financial Hedging Gain/Loss Natural Gas Index Swaps 141

142 Analyst Day - November 2013 Corporate Hedging Overview The Impact of Firm Sales on Realized Price Long-Term Firm Sales (1) (MMBtu per Day) 400, , , ,000 0 (1) Long-term firm sales represent gross volumes 307,745 NYMEX 202,745 Less: $0.284 Dominion 105,000 Less: $0.265 Winter 2013/2014 Determining the Price of a Firm Sales Contract With a $4.25/MMBtu Hedge at the Reference Point Contract Reference Point NYMEX Dominion 244,091 December Settlement $4.000 $ ,000 Less: Average Sales Basis Differential ($0.284) ($0.265) Average Realized Price (Before Hedging) $3.716 $3.235 NYMEX 149,091 Less: $0.281 Dominion 95,000 Less: $0.305 Summer 2014 NYMEX 150,000 Less: $0.257 Dominion 55,000 Less: $0.236 Winter 2014/

143 Analyst Day - November 2013 Corporate Hedging Overview Pairing Firm Sales with Hedges Leads to Price Certainty Long-Term Firm Sales (1) (MMBtu per Day) 400, , , ,000 0 (1) Long-term firm sales represent gross volumes 307,745 NYMEX 202,745 Less: $0.284 Dominion 105,000 Less: $0.265 Winter 2013/2014 Determining the Price of a Firm Sales Contract With a $4.25/MMBtu Hedge at the Reference Point Contract Reference Point NYMEX Dominion 244,091 December Settlement $4.000 $ ,000 Less: Average Sales Basis Differential ($0.284) ($0.265) Average Realized NYMEX Price (Before Hedging) $3.716 $3.385 December Hedge 149,091 $4.250 $4.250 Less: $0.281 NYMEX Less: December Settlement $4.000 $3.650 Dominion 95,000 Less: $0.305 Summer ,000 Less: $0.257 Hedge Gain $0.250 $0.600 Average Realized Price (After Hedging) $3.966 $3.985 Dominion 55,000 Less: $0.236 Winter 2014/

144 Analyst Day - November 2013 Corporate Hedging Overview Price Certainty only if Firm Sales & Hedge Index Match Long-Term Firm Sales (1) (MMBtu per Day) 400, , , ,000 0 (1) Long-term firm sales represent gross volumes 307,745 NYMEX 202,745 Less: $0.284 Dominion 105,000 Less: $0.265 Winter 2013/2014 Hedging Dominion Firm Sales Contracts With a $4.25/MMBtu Hedge at NYMEX vs. Dominion Contract Reference Point Dominion Dominion 244,091 December Settlement $3.650 $ ,000 Less: Average Sales Basis Differential ($0.265) ($0.265) Average Realized Price (Before Hedging) NYMEX $3.385 $3.385 Hedge Reference 149,091 Point NYMEX Dominion Less: $0.281 NYMEX December Hedge $4.250 $ ,000 Less: December Settlement Less: $4.000 $0.257 $3.650 Hedge Gain $0.250 $0.600 Dominion Average Realized Price (After Hedging) Dominion $3.635 $ ,000 Less: $0.305 Summer ,000 Less: $0.236 Winter Difference: $ /2015 Dominion to NYMEX Basis 144

145 Analyst Day - November 2013 Corporate Hedging Overview FY 2014 Production Firm Sales & Hedge Composition Total Production (Bcfe) Bcf EDA NYMEX Firm Sales Seneca has an additional 12.7 Bcf of NYMEX hedges to help mitigate commodity exposure on its WDA sales 30 Bcf Price Certainty 100% $4.24 /MMcf EDA DOM Firm Sales 25 Bcf Price Certainty 92% $4.26/MMcf EDA Spot Sales 29 Bcf WDA Production Total East Division Production 145

146 Analyst Day - November 2013 Corporate Financial Overview 146

147 Analyst Day - November 2013 Corporate National Fuel Gas Company Targeting Sustained Growth for the Next Five Years Adjusted EBITDA ($ Millions) $1,250 $1,000 $750 $500 $250 $0 Exploration & Production Segment Gathering Segment Pipeline & Storage Segment Utility Segment Energy Marketing & Other $581 $280 $632 $668 $327 $377 $704 $397 $852 $492 $131 $121 $111 $137 $161 $164 $167 $169 $160 $172 $ Forecast Fiscal Year Note: A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings is included at the end of this presentation % Forecasted EBITDA CAGR 2015 Forecast 147

148 Analyst Day - November 2013 Corporate National Fuel Gas Company Capital Spending Adjusts to Capitalize on Opportunities Capital Expenditures ($ Millions) $1,500 $1,250 $1,000 $750 $500 $250 $0 Exploration & Production Segment Gathering Segment Pipeline & Storage Segment Utility Segment Energy Marketing & Other $650- $750 $550- $694 $650 $501 $649 $533 $100- $150 $398 $100- $80 $225- $188 $150 $115- $275 $129 $144 $55 $53 $38 $56 $135 $56 $58 $58 $58 $72 $80-$90 $80-$90 $307 (1) $854 $977 $717 $845- $1, Forecast Fiscal Year $1,055- $1, Forecast Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. (1) Does not include the $34.9 MM Seneca Resources Corporation s acquisition of Ivanhoe s U.S.-based assets in California, as this was accounted for as an investment in subsidiaries on the Statement of Cash Flows, and was not included in the Exploration & Production segment s Capital Expenditures 148

149 Analyst Day - November 2013 Corporate National Fuel Gas Company Forecasting a Modest Outspend in 2014 $ Millions $1,500 $1,000 $500 $0 $175 +/- $835 +/ Forecast ~$125 $935 +/- $347 +/- $940 (1) +/ Forecast ~$127 $1,160 +/- Cash from Ops Change in Cash & Other New Financing CapEx Dividend (1) Forecasted cash from operations for Fiscal 2015 is projected assuming a 12.5% growth rate on 2014 forecasted results 149

150 Analyst Day - November 2013 Corporate National Fuel Gas Company Maintaining a Strong Balance Sheet Average Debt / Adjusted EBITDA Debt / Adjusted EBITDA Fiscal Year Note: A reconciliation of Adjusted EBITDA to Net Income is included at the end of this presentation (1) Long-Term Debt of $1.649 billion Shareholders Equity 57% Capitalization Total Debt (1) 43% $3.843 Billion As of September 30,

151 Analyst Day - November 2013 Corporate National Fuel Gas Company Strong Liquidity with an Investment Grade Rating $600 $500 $400 $300 $200 $100 $0 Ratings/ Outlook 5.58% Embedded Cost of Long-Term Debt Moody s Baa1 Stable Standard & Poor s BBB Stable Fitch BBB+ Stable $300 $250 $ % 8.75% 4.9% Fiscal Year $549 $ % $49 Liquidity ($Millions) $ % 7.375% Cash and Temporary Investments $ 65 Available Short-Term Credit Facilities $1,085 Total Short-term Liquidity $1,

152 Analyst Day - November 2013 Corporate National Fuel Gas Company Focused on Delivering Strong Returns Annualized Return on Capital 12% 8% 4% 0% Three-Year Annualized Return on Capital NFG (Fiscal Years) (Fiscal Years) (12-Months Ended 6/30) NFG Percentile 81% 75% 88% 152

153 Analyst Day - November 2013 Corporate National Fuel Gas Company Dividend Track Record Annual Dividend Rate $2.00 $1.50 $1.00 $0.50 $0.00 (1) As of November 14, 2013 Dividend Consistency Consecutive Dividend Payments Consecutive Dividend Increases Current Annualized Dividend Rate Annual Rate at Fiscal Year End 111 Years 43 Years $1.50 per Share Current Dividend Yield (1) 2.1% 153